Subsea Processing of Well Fluids

ABSTRACT

A wax control element for subsea processing of well fluids in a wellstream comprises a bundle of flowlines within an elongate tensile structure. That structure defines inlet and outlet ends and has cooling and heating provisions that act on the flowlines, in use, to promote deposition of wax in the flowlines and subsequent entrainment of wax in the wellstream.

This invention relates to subsea processing or treatment of well fluidsin oil and gas production from subsea wells. Some embodiments of theinvention employ a wax removal system to enable ‘cold flow’ oil and gastransportation in a subsea environment.

After extraction at a subsea wellhead, well fluid (which may comprisecrude oil and/or natural gas) is carried as a wellstream along a seabedpipeline or ‘tie-back’ and then up a riser to a surface unit fortemporary storage and onward transportation. Some examples of surfaceunits are platforms, Floating Process, Storage and Offloading vessels(FPSOs), onshore plants and Floating Liquefaction of Natural Gas vessels(FLNGs). Tie-backs can extend for many kilometres; there is a trendtoward longer tie-backs, 150 km for example, as oil and gas productionextends into deeper and more challenging waters.

At some point, the wellstream must be processed, for example to separateout water, gas and solid-phase material such as sand entrained in thewellstream. Processing may be performed at the surface unit but over thepast twenty years, there has been a drive to adopt subsea processing.Subsea processing may also involve pre-processing, allowing for furtherprocessing steps to take place at the surface unit.

In general, subsea processing of the wellstream may involve pumping toincrease its flow rate and/or pressure; separation of sub-products suchas water, gas and solid-phase material; and warming or cooling thewellstream to achieve the best flow rate. More specifically, subseaprocessing technology encompasses functions such as manifolding,water/oil/gas separation, water cleaning, boosting, water re-injection,de-waxing, gas compression, power supply and controlling.

The main market drivers for subsea processing are increasedproductivity, increased recovery, improved flow assurance, longertie-back distances and reduced topside processing requirements. Inparticular, subsea processing may simplify flow assurance in thepipeline and in the riser, improve production efficiency and improve theintegrity of the pipeline and the riser. In this respect, the wellstreamcan only pass up the riser to reach a surface processing unit if thewellstream has a high enough pressure, temperature and flow rate at thebottom of the riser. For example, if the temperature is too low and ifthere is enough water in the wellstream, wax or hydrate compounds mayform and deposit inside the pipeline and so restrict or eventually blockthe flow. Also, subsea processing removes potentially damaging contentof the wellstream, such as water and sour compounds (for example H₂S)that promote corrosion and sand that causes erosion.

FIGS. 1 and 2 are greatly-simplified schematic diagrams of prior artsolutions that involve subsea processing of a wellstream. Like numeralsare used for like features. The direction of production flow in eachcase is from left to right as shown, from a wellhead 10 along a pipeline12 laid across the seabed 14 to a riser 16. The pipeline 12 has one ormore termination structures 18 that may, for example, be a Pipeline EndTermination (PLET) or a manifold that gathers well fluid coming fromseveral lines and may also include one or more pig launchers/receivers.A subsea processing unit 20 receives and processes the wellstream beforeit flows up the riser 16. Jumper pipes or spools 22 are used to connectthe various elements as shown. A power umbilical 24 shown in FIG. 1extends from a surface unit (not shown) to provide power to the subseaprocessing unit 20.

The solutions in FIGS. 1 and 2 differ in the relative positions of thepipeline 12 and the processing unit 20. In FIG. 1, the processing unit20 is downstream of the pipeline 12, interposed between the pipeline 12and the riser 16. The riser 16 is shown here in the form of a risercolumn or tower. Conversely, FIG. 2 shows the processing unit 20upstream of the pipeline 12, interposed between the wellhead 10 and thepipeline 12. FIG. 2 also shows that the riser 16 may take the form of acatenary riser.

In practice, subsea processing systems comprise multiple subseaprocessing units such as multiphase pumps, gas compression units andseparators. Specific examples of subsea units are: a separation moduleas disclosed in WO 03/078793; a multiphase separation unit as disclosedin WO 03/087535; a compressor as disclosed in WO 2012/163996; anelectronics module as disclosed in WO 2008/037267; and a separationvessel as disclosed in WO 2010/151392. Subsea processing systems may beconfigured to suit the characteristics of individual fields such asreservoir depth, pressure, temperature, gas-oil ratios, water cut andthe distance to host facilities.

Subsea processing units may be very bulky: for example, subseaseparators may weigh around 1000 tonnes each. To some extent, thisreflects oversizing for maximum reliability during the lifetime of thefield, hence increasing the cost, size and weight of each unit.

Other challenges of subsea processing include congestion of the seabednear the wellheads, poor accessibility for maintenance and repair, andthe need for additional umbilicals to power the various subseaprocessing units.

A particular challenge of subsea processing systems is their complexinstallation and tie-in methodology. Typically, the pipeline 12 isinstalled between the wellhead 10 or a manifold and the target locationof the subsea processing unit 20. Then, the subsea processing unit 20(including its foundations) is installed by lifting it and lowering itto its target location, whereupon the pipeline 12 and the subseaprocessing unit 20 are tied by jumpers or spools 22. Umbilicals 24 areinstalled between the subsea processing unit 20 and a surface unit. Theprocess requires various different installation vessels to be on site,some of which must be equipped with large cranes, and so involves hugecost and a lengthy timescale. Of course, the cost and timescale may beincreased unexpectedly by the need to wait for acceptable weatherconditions before performing each installation step.

Previously-qualified subsea processing units have been proposed ordesigned and installed, and are in use to varying degrees around theworld. However, subsea processing remains a young technology in which itis vital to demonstrate reliability and serviceability of the system andits component units.

In many applications of the invention, the processed well fluid will becrude oil. Wherever the wellstream is dominated by oil, there is athreat of wax deposition on the inside of multiphase flow lines as thetemperature of the wellstream falls below the wax formation temperature.It is known to deal with this issue by forcing wax formation uponcooling the wellstream in a Wax Control Unit or WCU, as used in a typeof subsea processing called ‘cold flow’. Cold flow refers totransportation of cold product which, for oil, typically means at atemperature below 50° C. Cold flow avoids the need for additionalinsulation or heating of the pipeline, which reduces the cost and allowsa longer tie-back pipeline across the seabed between the wellhead andthe riser.

In the WCU, the wellstream is cooled by heat exchange with cooling wateraround the flowline. This cools the wellstream enough to force wax todeposit on the inner wall of the flowline at predetermined locations.The wax deposits are removed by periodic, limited heating at thoselocations when feedback sensors indicate that the wax thickness isapproaching an acceptance limit for a flowline section. Heating causesthe wax layer to melt off and fall into the wellstream, where it isentrained to form a slurry that can be transported under cold flowconditions along a tie-back and to the surface unit.

Cold flow is known for onshore oil production but its applicability tosubsea production is limited by constraints on installation andaccessibility. However, some prior art disclosures of subseaapplications are acknowledged below. In general, they will requiresubsea processing equipment that comprises discrete units separate fromthe pipeline, such as in WO 2012/099344, and so will require multipleinstallation steps.

U.S. Pat. No. 3,590,919 describes the principle of a cold flow subseafield, in which processing satellite units are arranged in the fieldnear the wellheads. More recently, WO 2009/051495 describes subsea coldflow in a pipe-in-pipe arrangement with pulsed heating.

WO 2006/068929 discloses a cold flow production system in which aninitial cooler unit forces the formation of wax in a slurry catcher.Then the remaining flow is transported into the pipeline system. Anexample of a slurry catcher is disclosed in WO 2010/009110. All unitsare separate from the pipeline and connected by jumpers. The slurrycatcher must be cleaned out periodically using a pigging system.

In U.S. Pat. No. 5,154,741, crude oil flow is treated to separate oiland gas and to transport gas without risk of hydrate formation byremoving condensates. The fluids are not transported under cold flowconditions: there is no mention of cooling.

WO 00/25062 describes a cold flow system in which additional gashydrates are injected into the oil flow before cooling, in order toincrease the rate of initial wax formation and to remove all wax atonce. This leaves no residual water.

A cold flow system disclosed in WO 2007/018642 is connected to anonshore installation but the method of installation is not specified.Conversely in WO 2012/149620, depressurising modules are added along thepipeline to avoid formation of wax and hydrates. Also, WO 2004/033850describes a coiled pipe that is inserted into the pipeline for flowassurance purposes but with no subsea processing.

It is known to group subsea units onto one frame or into one structureso as to require as few installation operations as possible. Forexample, a combined towing head for a flowline bundle is described inOTC 6430 (OTC Conference, 1990), where the head includes valves,connectors and manifolds to connect to a wellhead or to wellheadjumpers. In effect, the head is a combination of a conventional PLET,manifold and towhead. A similar arrangement is disclosed in EP 0336492.However, the towing head assembly is essentially passive and has nointegral treatment or processing capability. The towing head is not usedfor processing but for pulling the bundle: some buoyancy or ballast maybe added for this purpose. Also, most prior art relating to bundles isconcerned with heating or hot bundles and not with cooling thewellstream.

In this respect, a manifold may be distinguished from a processing unit:the latter can modify the nature, temperature and/or composition of wellfluid whereas the former cannot. In contrast, a manifold acts only onflow rate without pumping, and essentially includes only piping andvalves although it may also include sensors and control system forvalves.

US 2004/0040716 discloses a pipe-in-pipe flowline in which ahydrocarbon-transporting pipe is placed coaxially within an outercarrier pipe and the annulus between the pipes is filled with thermallyinsulating material. The hydrocarbon liquid has its temperaturemaintained above solidification/precipitation temperature by heat froman active heating system involving hot liquid being passed along theannulus. US 2003/0056954 discloses a flow-assurance system in which aninner pipe is disposed within an outer pipe to assure flow through theouter pipe. Hot fluids pass through the inner pipe to maintain thetemperature of the fluids flowing through the outer pipe; also,chemicals may flow through the inner pipe to condition the fluids in theouter pipe. These documents do not disclose cold flow: they merelyrepresent the prior art background to cold flow.

US 2009/0020288 discloses a flow-assurance system that involves chillinga hydrocarbon production flow in a heat exchanger and causing solids toform and then periodically removing deposits and placing them in aslurry by using a closed-loop pig launching and receiving system. Thisis a variant of cold flow but is of no more than background relevance tothe invention.

Against this background, the invention resides in a wax control elementfor subsea processing of well fluids in a wellstream, the elementcomprising a bundle of flowlines within an elongate tensile structurethat defines inlet and outlet ends and that has cooling and heatingprovisions for acting on the flowlines, in use, to promote deposition ofwax in the flowlines and subsequent entrainment of wax in thewellstream.

The tensile structure may, for example, be an outer pipe surrounding theflowlines. Flowlines are preferably disposed in parallel but connectedin series within the tensile structure such that the wellstream reversesin flow direction between one flowline and the next within the element.

A power connection may extend along the element between the inlet andoutlet ends; similarly a data connection may extend along the elementbetween the inlet and outlet ends.

The inventive concept also embraces a towable unit for controlling waxin subsea well fluids, comprising a wax control element of the inventionwhose tensile structure extends between, and is capable of acting intension between, a first towhead at an upstream end of the element and asecond towhead at a downstream end of the element.

At least one of the towheads, most preferably the first, upstreamtowhead, preferably has an on-board processing facility for processingthe well fluids, which facility effects at least separation of waterphases that are present in the well fluids. A power station may behoused in the second, downstream towhead, in which case an umbilicaldistribution system for distributing power and/or chemicals to externaltemplates or satellite wellheads is preferably also housed in thesecond, downstream towhead.

The first, upstream towhead suitably also comprises facilities selectedfrom a set comprising: connections to wellhead(s) or to a productionmanifold; water separation; removed water treatment and/or re-injection;cold flow conditioning for transportation; cold-water circulationsystems; pigging facilities; and local heating systems for wax removal.

At least one and optionally both of the towheads may have a pump forpumping cooling water along the element to cool its flowlines;similarly, at least one and optionally both of the towheads may have aheating system for applying heat to flowlines of the element.

The inventive concept extends to a subsea oil or gas production systemcomprising at least one wax control element of the invention or at leastone towable unit of the invention.

The inventive concept also extends to a method of installing ordeveloping a subsea oil or gas production system by installing aprefabricated wax control unit at an installation location, the unitcomprising an elongate wax control element disposed between a firsttowhead at an upstream end of the element and a second towhead at adownstream end of the element, the method comprising: towing the unit tothe installation location with an elongate tensile structure of the waxcontrol element in tension between the towheads; sinking the unit at theinstallation location; and connecting the towheads to other elements ofthe production system so that the unit may be operated to pass the wellfluid along the wax control element.

Wax control may be effected by passing well fluid along the wax controlelement between the towheads while cooling and periodically heatingflowlines of the wax control element.

Thus, the unit may be operated to pass well fluid along a bundle offlowlines within the elongate tensile structure of the wax controlelement, whereby cooling and heating of the flowlines can promotedeposition of wax in the flowlines and subsequent entrainment of wax ina wellstream of the well fluid.

The invention therefore contemplates a wax control unit that isintegrated into a bundle system. A pipe-in-pipe heat exchanger mayensure that the wellstream is cooled down sufficiently to enable aforced wax deposit at the flowline inner wall. In preferred embodiments,three pipe sections of individual lengths of about 1.0 to 2.0 km arerouted within a bundle carrier pipe. Each pipe section is surrounded byindividual sleeve pipes in a pipe-in-pipe arrangement.

In preferred embodiments, the invention is part of a system solution tointegrate required functions for subsea processing into towheadstructures for bundles. Towhead structures and an intermediate bundlesection form a unit that functions as a subsea processing centre forsurrounding subsea production satellites and templates and that can beused for long-distance tie-back of subsea field developments. By doingso, the invention provides a new concept for subsea processing thatprovides reliable and flexible solutions for field developments.

Among the benefits of incorporating the processing units into bundlesand their towheads is that the system can be prefabricated, assembledand tested onshore before towing to the field for installation. As notedpreviously, the reliability of subsea processing equipment is crucial inensuring the success of any subsea processing project. Onshoreprefabrication and testing greatly improves the reliability of thesystem, as compared with connecting up units at a subsea location andperforming tests there. An additional improvement in reliability arisesfrom a drastic reduction in the number of subsea-connected interfaces.

The weight of subsea processing units increases with each addedfunction, yet the invention allows an installation method without theuse of large crane vessels. For example, the system can be towed to thefield using the ‘controlled depth tow’ method, which ensures low-stressinstallation without the use of large crane vessels being dependent onlow installation sea states. This makes installation less weathersensitive, and reduces the cost of installation vessels significantly.In general, therefore, the invention provides a compact and flexiblelayout with reduced cost from a fast and simple installation.

The introduction of a towed processing system for cold flow ofhydrocarbons as described in this specification promises to fulfil theindustry vision of ‘subsea factories’. By including components that canreceive well fluids from different in-field flowlines, separate thewellstream to remove contaminants, cool the wellstream and at the sametime continuously assure the flow at low temperatures and sufficientpressure, the system may significantly affect the design of pipeline andriser systems. The design of downstream pipeline and riser systems canbe simplified as their temperature requirements are consequentlyrelaxed.

By introducing a pre-tested processing centre that can process and cooldown the wellstream, it is possibly also to simplify the pipeline andriser systems against the host platform. Such pipeline and riser systemscan then be manufactured without the use of insulation and active orpassive heating. This enables longer tie-back distances at a relativelylow cost and with reduced power consumption, which will make certainfield developments more favourable.

A pre-processing central unit of the invention can work in manydifferent configurations. For example, it can serve as a manifold forindividual wells located in a specific area or it can be tied directlyin to a larger subsea template.

The invention provides a new method for design, fabrication,installation and operation of oil- or gas-dominated field developments,as the compact layout of the subsea processing centre can be configuredto suit both oil-or gas-dominated wellstreams.

Where the processed fluid is crude oil, wax removal may be performed butin a first step, a separation unit allows separation of at least waterfrom other components of the crude oil. This water can be re-injectedinto the well. This reduces the maximal quantity of wax susceptible tobe generated when cooling the crude oil. The next step, which isoptional, may include gas separation, sand removal and injection ofchemicals into the wellstream.

Then, the crude oil (with any residual water) is cooled down by thermalexchange with the surrounding water. The oil circulates in apipe-in-pipe arrangement whose annulus is filled by pumped cold water.The resulting cooling generates wax deposits in identified locations.The pipe-in-pipe is convoluted into a long bundle in which the flow mayreturn several times within the cooling unit to force wax deposits nearthe upstream, process end of the system. The system may be connected toa riser at the downstream end. Wax deposits are removed by periodic,limited heating at determined locations. Pigging facilities, which maybe removable, may be used to test and maintain the pipeline.

In order that the invention may be more readily understood, referencewill now be made, by way of example, to the accompanying drawings, inwhich:

FIG. 1 is a schematic diagram of a prior art solution involving subseaprocessing of a wellstream, in which a processing unit is disposeddownstream of a pipeline;

FIG. 2 is a schematic diagram of another prior art solution involvingsubsea processing of a wellstream, in which a processing unit isdisposed upstream of a pipeline;

FIG. 3 is a schematic diagram of a subsea processing solution of theinvention employing a towable unit comprising a pipeline bundle with atowhead at each end;

FIG. 4 is a top plan view of a towable unit of the invention in apractical form;

FIG. 5 is a schematic plan view of an upstream towhead used in a towableunit of the invention;

FIG. 6 is a schematic plan view of a downstream towhead used in atowable unit of the invention;

FIGS. 7a and 7b show, respectively, towing and installation stepsperformed with the towable unit of the invention;

FIG. 8 is a top plan view of a subsea production installationincorporating the towable unit of the invention;

FIG. 9 is a perspective view of a variant of the upstream towhead shownin the towable unit of FIG. 4;

FIG. 10 is a top plan view of a towable unit of the invention includingthe variant of the upstream towhead shown in FIG. 9;

FIG. 11 is a schematic plan view of a prior art solution for waxcontrol; and

FIG. 12 is a schematic cross-sectional view of a pipeline bundle for waxcontrol in accordance with the invention.

Reference has already been made to FIGS. 1 and 2 of the drawings todescribe subsea processing solutions known in the prior art. FIG. 3illustrates the invention in a similarly simplified, schematic style;again, like numerals are used for like features. Thus, the direction ofproduction flow is again from left to right as shown, from a wellhead 10to a riser 16. The riser 16 is shown here in the form of a riser columnor tower like that of FIG. 1, but it may of course take another formsuch as a catenary.

In FIG. 3, the pipeline 12 laid across the seabed 14 between thewellhead 10 and the riser 16 is replaced by a pipeline bundle 26. Also,the termination structures 18 of FIGS. 1 and 2 are replaced by anupstream towhead 28 at an upstream end of the pipeline bundle 26 and adownstream towhead 30 at a downstream end of the pipeline bundle 26.Thus, the upstream towhead 28 is interposed between the wellhead 10 andthe pipeline bundle 26 whereas the downstream towhead 30 is interposedbetween the pipeline bundle 26 and the riser 16.

In accordance with the invention, either and preferably both of thetowheads 28, 30 comprises facilities for processing the wellstreambefore it flows up the riser 16, and so also replaces the processingunit 20 of FIGS. 1 and 2. Thus, either and preferably both of thetowheads 28, 30 serves as an integrated termination structure andprocessing unit. The invention therefore aims to mitigate several of thedrawbacks of subsea processing by grouping subsea processing units withthe pipeline bundle 26. Also, distributing the processing units amongthe towheads 28, 30 spreads the weight of the process system and locatesthe units appropriately at the inlet or outlet end of the pipelinebundle 26.

The pipeline bundle 26 and the towheads 28, 30 together constitute asingle towable unit 32 that, highly advantageously, may be fabricatedand tested onshore before being towed as one unit to an installationsite. Once fabricated onshore, the whole unit 32 may be pulled into thewater, as is already done in the oil and gas industry with the pipebundles that form hybrid riser towers.

In the context of towing, the upstream towhead 28 may be described as aleading towhead and the downstream towhead 30 may be described as atrailing towhead. Towing and installation will be described in moredetail below with reference to FIGS. 7a and 7b of the drawings.

The pipeline bundle 26 acts in tension between the towheads 28, 30during towing, with tensile loads being borne by the pipes of the bundle26 or, preferably, principally or exclusively by an outer pipe or otherprotective structure that surrounds the pipes of the bundle 26. Thisarrangement will be described in more detail below with reference toFIG. 12 of the drawings.

In the simplified arrangement shown in FIG. 3, jumper pipes or spools 22connect the upstream towhead 28 to the wellhead 10 and the downstreamtowhead 30 to the riser 16. However, the towheads 28, 30 may beconnected to the wider subsea production system in other ways, forexample via manifolds, and so need not be connected as directly to thewellhead 10 and to the riser 16.

As FIG. 6 will show later, a power umbilical as shown in FIG. 1 mayextend from a surface unit (not shown) to one of the towheads 28, 30 toprovide power to its processing facilities. Advantageously, power may betransmitted from one towhead 28, 30 to the other towhead 28, 30 throughpower cables in the pipeline bundle 26. This allows one umbilical to beconnected to just one of the towheads 28, 30 and yet to provide power toboth of the towheads 28, 30.

FIG. 4 shows the towable unit 32 in a practical form, with a longpipeline bundle 26 connecting a larger upstream towhead 28 and a smallerdownstream towhead 30. As will be explained, the upstream towhead 28includes a manifold in this instance and so is optimised to gather fluidproduction from multiple wellheads. A variant of the upstream towhead 28that encompasses the wellhead or provides drilling slots will bedescribed later with reference to FIGS. 9 and 10.

Moving next to FIGS. 5 and 6, these show the towheads 28, 30 in moredetail. Specifically, FIG. 5 shows the upstream towhead 28 whereas FIG.6 shows the downstream towhead 30.

The upstream towhead 28 shown in FIG. 5 comprises an elongate tubularsteel lattice frame 34 of generally rectangular cross-section. As anon-limiting example, the frame 34 may be considerably in excess offorty metres long and more than eight metres high and wide. The frame 34comprises four parallel longitudinal members 36 joined by cross-members38, with gaps between the cross-members 38 providing access to bays forinstallation, maintenance and replacement of processing andflow-handling equipment carried by the towhead 28. The processing andflow-handling equipment is largely carried within the cross-section ofthe frame 34, although some elements of that equipment may protrude fromthe frame 34.

FIG. 5 shows processing and flow-handling equipment carried by theupstream towhead 28. At its upstream end, the frame 34 of the towhead 28defines a bay that houses a manifold 40 for in-field flowlines and forwater injection. At its downstream end, the frame 34 has a tapering nosestructure 42 to anchor one end of the pipeline bundle 26 against tensileloads. From there, the pipeline bundle 26 extends over a considerabledistance (typically 1.5 to 2.0 km) to the downstream towhead 30, whichwill be described later with reference to FIG. 6. The frame 34 alsocarries a system control module 44 that may be connected through thepipeline bundle 26, as shown, to control the downstream towhead 30.

It has been noted above that where the processed well fluid is crudeoil, there is a threat of wax deposition as the temperature of thewellstream falls below the wax formation temperature. Wax deposition iscontrolled by wax control features in the pipeline bundle 26. This isthe purpose of a cooling water pump 46, which drives cooling water alongthe pipeline bundle 26 as will be explained later with reference toFIGS. 11 and 12 of the drawings. However, there is also a threat ofhydrate formation as the temperature of the wellstream falls below thehydrate formation temperature. Consequently, much of the equipmentbetween the manifold 40 and the pipeline bundle 26 is concerned withhydrate control.

The effect of hydrate formation can be significantly reduced, indeedalmost eliminated, by separating water out of the wellstream.Consequently, the hydrate control equipment of the upstream towhead 28comprises two separation stages 48, 50 downstream of the manifold 40,followed by a coalescer 52. Subsea separation of water is a known andqualified technology that typically leaves less than 2% of water in thewellstream after a two-stage separation. The small amount of waterremaining in the wellstream can be handled by adding anti-agglomeratesto the wellstream at a hydrate control unit 54 after separation andcoalescence.

Separated water is cleaned in a hydro-cyclone 56 and then re-injectedinto the reservoir via the manifold 40 by using a booster pump 58 and awater injection pump 60.

Routine optional steps of gas separation and sand removal may also beperformed by equipment in the upstream towhead 28, although thatequipment has been omitted from FIG. 4 for clarity.

Pigging facilities (which may be removable) are provided to test andmaintain the pipeline and particularly the pipes of the pipeline bundle26. A removable pig launcher 62 is shown in FIG. 4. However, it shouldbe noted that systematic pigging such as is required by WO 2006/068929is obviated by first separating water from the crude oil as describedabove, which drastically reduces the residual quantity of wax andhydrates.

Turning now to the downstream towhead 30 shown schematically in FIG. 6,this also comprises an elongate tubular steel lattice frame 64 ofgenerally rectangular cross-section comprising four parallellongitudinal members 66 joined by cross-members 68. The downstreamtowhead 30 is somewhat shorter than the upstream towhead 28 but issuitably of similar cross-sectional size.

The frame 64 of the downstream towhead 30 carries a pipeline connector70 communicating with the pipeline bundle 26 for downstream transport ofthe wellstream. For example, there may be cold-flow transport of thewellstream along a long tie-back pipeline on the seabed, or thewellstream may be carried by a jumper or spool into an adjacent riserstructure.

A second cooling water pump 72 mirrors the cooling water pump 46 of theupstream towhead to drive cooling water along the pipeline bundle 26.This duplication of water pumps 46, 72 minimises pumping losses andprovides redundancy to maintain cooling in the event of failure ordowntime due to maintenance.

The frame 64 of the downstream towhead 30 also carries a power station74 that takes electrical power from a riser umbilical 76. The powerstation 74 supplies power to: an umbilical distribution system 78; toother equipment carried by the frame 60, such as the cooling water pump72; and also via the pipeline bundle 26, as shown, to power the upstreamtowhead 28. The umbilical distribution system 78 includes connectionpoints for plugging in umbilicals as well as fuses and transformers.Those features are routine and need no elaboration here.

In summary, therefore, the upstream towhead 28 includes: connections towellhead(s) or to a production manifold; water separation; removed watertreatment and/or re-injection; cold flow conditioning fortransportation; cold-water circulation systems and local heating systemsfor wax removal. However cold-water circulation systems and localheating systems could also, or alternatively, be located in thedownstream towhead 30. It is also possible for pigging facilities to belocated on either towhead 28, 30.

Turning next to FIGS. 7a and 7b of the drawings, pipeline installationby towing is well known in the art. In this respect, a convenient towingtechnique for use with the invention is the Controlled Depth TowingMethod (CDTM), which is described in technical papers such as OTC 6430noted previously. This technique involves far fewer installation stepsthan in prior art subsea processing systems and it does not requireinstallation vessels with particularly large cranes or great liftcapacity. At the installation site, the towable unit 32 can be loweredinto a predetermined gap in the subsea production system in a ‘plug andplay’ manner, whereupon the unit 32 may be connected via jumpers orspools at each towing head 28, 30 to other elements of the productionsystem, which may be placed on the seabed before or after the unit 32.

Reference is made to OTC 6430 for a more detailed description of theCDTM technique but a brief description follows in the context of thepresent invention. The CDTM principle involves the transportation of aprefabricated and fully-tested towable unit 32 suspended on towing lines80 between two installation vessels 82, which may be tugs. A thirdvessel 84 may be employed for monitoring purposes as shown in FIG. 7a .An outer pipe surrounding the pipeline bundle 26 may be used to define achamber to adjust buoyancy, or buoyancy may be adjusted by modulesattached to the pipeline bundle 26. Chains 86 attached to the pipelinebundle 26 provide additional weight so that, at rest, the pipelinebundle 26 floats clear of the seabed 88 but beneath the influence ofwave action near the surface 90.

When the towable unit 32 reaches the installation location, it islowered toward the seabed 88 by reducing its buoyancy, for example byflooding the outer pipe surrounding the pipeline bundle 26, while thetowing lines 80 are paid out from the installation vessels 82. Thetowable unit 32 then settles on the seabed 88 as shown in FIG. 7b ,whereupon tie-ins to prelaid elements 92 of the subsea production systemcan be made, for example using jumpers or spools (not shown) fitted withsuitable known connectors.

FIG. 8 shows in more detail how the towable unit 32 fits into a subseaproduction system 94. In this example, the subsea production system 94comprises two templates 96 and three satellite wellheads 98. Thetemplates 96 are supplied with power and chemicals from the downstreamtowhead 30 through primary umbilicals 100. Secondary umbilicals 102supply power and chemicals from the templates 96 to the satellitewellheads 98. Such chemicals may be remediation fluids such as methanolor diesel oil that may be injected for maintenance purpose into thevalves of a wellhead, after a shutdown, to remove wax where it mayappear. The templates 96 are also supplied with water for injection fromthe manifold 40 of the upstream towhead 28 through water lines 104.

Production flowlines 106 carry well fluids from the templates 96 and thesatellite wellheads 98 back to the manifold 40 of the upstream towhead28 for processing as described previously. The resulting wellstream thenpasses along the pipeline bundle 26 for wax control before passingthrough a spool 108 to a Pipeline End Module (PLEM) 110 for onwardtransport in a cold flow state.

FIG. 9 shows a variant 112 of the upstream towhead 28 shown in FIG. 5.FIG. 10 shows that upstream towhead variant 112 in the context of atowable unit that also comprises a pipeline bundle 26 and a downstreamtowhead 30 as previously described.

The upstream towhead variant 112 has an elongated frame 114 to encompasswellheads 116 or to provide a corresponding array of drilling slots.Again, the processing and flow-handling equipment is largely carriedwithin the cross-section of the frame 114. However, some equipment mayprotrude from the frame 114, such as the wellhead equipment 118 seenprotruding from the top of the frame 114 at its upstream end to the topright in FIG. 9. The open-topped structure of the frame 114 isbeneficial in this respect; some such equipment 118 may be landed intothe frame 114 after the upstream towhead variant 112 has been installedon the seabed.

Moving on finally now to FIGS. 11 and 12 of the drawings, these show howthe pipeline bundle 26 may be arranged to control wax formation. FIG. 12shows the pipeline bundle 26 of the invention but to illustrate thegeneral principle, FIG. 11 shows a prior art wax control system 120which will be described first.

The wax control system 120 of the prior art comprises long pipes 122laid on the seabed, in this example three pipes, each of which is about1.0 to 2.0 km in length. The pipes 122 are disposed in parallel about 10to 20 m apart on the seabed but are connected in series by spools 124.Consequently, the wellstream flows in a first direction through a firstpipe 122A, reverses direction in a first spool 124A, flows in theopposite direction through a second pipe 122B, reverses direction in asecond spool 124B, and flows back in the first direction through a thirdpipe 122C before exiting the wax control system 120. Having thereforetravelled between about 3.0 and 6.0 km in this example, the wellstreamexits the wax control system 120 in a much-cooled state.

The pipes 122 are each of pipe-in-pipe (PiP) construction to defineannular jackets 126 around flowlines 128. To cool the wellstream in theflowlines 128, pumps 130 pump raw seawater into the jackets 126 from oneend of the system 120, providing beneficial counterflow in the first andthird pipes 122A, 122C if not in the second pipe 122B. This cools thewellstream enough to force wax to deposit on the inner walls of theflowlines 128.

The wax deposits are removed periodically by localised heating whenfeedback sensors (not shown) indicate that the wax layer has reached alimiting thickness. Heating is achieved by heating cables 132 thatextend along the outside of the flowlines 128 within the annular jackets126; when powered by a power unit 134, the heating cables 132 cause thewax layer to melt off and become entrained in the wellstream.

The wax control system 120 of the prior art would be of no use for thepurposes of the present invention, where the pipeline bundle 26 is aptto be used as a tensile member in a towable unit 32, 114. In contrast,the pipeline bundle 26 of the invention shown in cross section in FIG.12 comprises an outer pipe 136 that surrounds three PiP sections 138.The PiP sections 138 are joined in series and extend in parallel likethe prior art shown in FIG. 11; there could be more or fewer of them.The outer pipe 136 protects, supports and retains the PiP sections 138and also bears most or all of the tensile loads experienced by thepipeline bundle 26 during fabrication, towing and installation of thetowable unit 32, 114.

It will, of course, be understood that the cross-sectional view of FIG.12 is simplified and omits details of coatings and linings as well asheating arrangements.

Cooling and heating may be achieved in various ways, although anadvantage of distributed water cooling pumps in both towheads 28, 30 isthat beneficial counterflow of cooling water may be achieved in all ofthe PiP sections 138. There must be an expansion loop at each end of themultiphase flowline allowing for expansion in the region of 0.5 m.

Each PiP section 138 is connected to a heating system 140 based on ACpower from the power station 74 of the downstream towhead 30. Theheating system 140 can be either a DEH (direct electrical heating) or aSECT (skin effect current tracing) system. The latter is currentlypreferred due to lower power requirements but this is not essential.Both heating techniques, and indeed others, will be known to the readerskilled in the art of subsea oil and gas engineering.

As no intermediate processing stations such as pump systems need to beinserted into the pipeline bundle 26, this allows the bundle geometry toremain the same along its length to ease both fabrication and mechanicaldesign.

1-14. (canceled)
 15. A method of installing or developing a subsea oilor gas production system by installing a prefabricated wax control unitat an installation location, the unit comprising an elongate wax controlelement disposed between a first towhead at an upstream end of theelement and a second towhead at a downstream end of the element, themethod comprising: towing the unit to the installation location with anelongate tensile structure of the wax control element in tension betweenthe towheads; sinking the unit at the installation location; andconnecting the towheads to other elements of the production system sothat the unit may be operated to pass the well fluid along the waxcontrol element passing well fluid along the wax control element betweenthe towheads while cooling and periodically heating flowlines of the waxcontrol element.
 16. (canceled)
 17. The method of claim 15, comprisingperforming hydrate control on the well fluid in the first, upstreamtowhead.
 18. The method of claim 17, wherein power and chemicals aredistributed to templates and wellheads of the system from the second,downstream towhead.
 19. A subsea oil or gas production system comprisingat least one towable unit for controlling wax in subsea well fluids,comprising a wax control element comprising a bundle of flowlines withinan elongate tensile structure that defines inlet and outlet ends andthat has cooling and heating provisions for acting on the flowlines, inuse, to promote deposition of wax in the flowlines and subsequententrainment of wax in the wellstream; the tensile structure of the waxcontrol element extends between, and is capable of acting in tensionbetween, a first towhead at an upstream end of the element and a secondtowhead at a downstream end of the element.